System and method for enhancing oil recovery from a subterranean reservoir

ABSTRACT

A system and method is disclosed for enhancing the distribution of an enhanced oil recovery fluid utilizing electrokinetic-induced migration for enhancing oil recovery from a subterranean reservoir. An enhanced oil recovery fluid is injected into the hydrocarbon bearing zone through the injection well. An electric field is generated through at least a portion of the hydrocarbon bearing zone to induce electrokinetic migration of the enhanced oil recovery fluid. Electrokinetic induced migration allows for the enhanced oil recovery fluid to contact portions of the reservoir that previously were unswept, which as a result enhances recovery of hydrocarbons through the production well.

CROSS-REFERENCE TO A RELATED APPLICATION

The present application for patent claims the benefit of U.S.Provisional Application bearing Ser. No. 61/425,517, filed on Dec. 21,2010, which is incorporated by reference in its entirety. Thisapplication is also a continuation-in-part claiming priority to Ser. No.13/161,885 having a filing date of Jun. 16, 2011, also incorporated byreference in its entirety.

TECHNICAL FIELD

The present invention generally relates to a system and method forenhancing oil recovery from a subterranean reservoir, and moreparticularly, to a system and method utilizing electrokinetic-inducedmigration to enhance the distribution of an enhanced oil recovery fluidwithin a subterranean reservoir.

BACKGROUND

Reservoir systems, such as petroleum reservoirs, typically containfluids including water and a mixture of hydrocarbons such as oil andgas. Primary, secondary, and tertiary recovery processes can be utilizedto produce the hydrocarbons from the reservoir.

In a primary recovery process, hydrocarbons are displaced from areservoir due to the high natural differential pressure between thereservoir and the bottomhole pressure within a wellbore. The reservoir'senergy and natural forces drive the hydrocarbons contained in thereservoir into the production well and up to the surface. Artificiallift systems, such as sucker rod pumps, electrical submersible pumps orgas-lift systems, are often implemented in the primary production stageto reduce the bottomhole pressure within the well. Such systems increasethe differential pressure between the reservoir and the wellbore intake;thus, increasing hydrocarbon production. However, even with the use ofsuch artificial lift systems only a small fraction of theoriginal-oil-in-place (OOIP) is typically recovered in a primaryrecovery process. This is the case because the reservoir pressure andthe differential pressure between the reservoir and the wellbore intakedeclines overtime due to production. For example, typically only about10-20% of the OOIP can be produced before primary recovery reaches itslimit—either when the reservoir pressure is too low that the productionrates are not economical, or when the proportions of gas or water in theproduction stream are too high.

To address the declining recoveries and increase the production life ofthe reservoir, secondary recovery processes can be used. Typically inthese processes, fluids such as water or gas are injected into thereservoir to maintain reservoir pressure and drive the hydrocarbons toproduction wells. Secondary recovery processes have already convertedbillions of barrels of proven oil resources to reserves, and typicallyproduce an additional 10-30% of OOIP to that produced during primaryrecovery. Additional actions such as optimizing rate allocation,mechanical and chemical conformance control, infill drilling, wellconversion, pattern realignment, or a combination thereof, can also betaken to improve the sweep efficiency in these flooding processes.

Despite these efforts, a significant amount of the OOIP still remainstrapped in the reservoir as conventional oil recovery methods (primaryand secondary) typically only extract up to about half the oil presentin a reservoir. As oil reservoirs age, oil recovery becomes increasinglydifficult. The hydraulic injection of fluid results in channeling of thefluid through higher permeability features, such as fractures or coarserlenses present within the reservoir, leaving other zones of thereservoir unswept. Furthermore, the unrecovered oil in the swept zonesis typically in the form of discontinuous blobs and globules trapped bycapillary pressure within the porous framework of the reservoir soil androck. Tertiary recovery processes such as chemical flooding (e.g.,surfactant, solvent or oxidant injection), gas miscible displacement(e.g., carbon dioxide or hydrocarbon injection), thermal recovery (e.g.,steam injection or in-situ combustion), microbial flooding, or acombination thereof, have been used in attempt to further increaserecovery from these depleted reservoirs.

Chemical flooding, which as used herein refers to an injection processusing a chemical or mixture of chemicals to enhance oil recoverytypically by reducing interfacial tensions and fluid viscosity in thereservoir, currently contributes to a small portion of tertiaryproduction. Despite recent advances in generating new chemicalformulations that have shown to successfully release trapped oilglobules from the porous framework of the reservoir, good contactbetween the injected chemical and oil is typically limited topreferential flow channels due to channeling of flow through highconductivity zones. Accordingly, the injected chemicals typically do notcontact the majority of trapped oil in the reservoir.

Polymer injections can supplement chemical floods (or water floods) byacting as a viscosity modifier, thereby reducing channeling and helpingto mobilize or drive the oil to a production well. In some embodiments,the polymer can be used to block the high conductivity zones orpermeability features, thereby diverting the injected fluids orchemicals into areas that have not previously been subjected to flow.However, the benefits of polymer injection are typically minimal becausethe radius of influence around a well where the polymer can move islimited leaving the flow dynamics throughout the majority of thereservoir unchanged. Therefore, the increased oil recovery resultingfrom a chemical flood has typically been low, such as less than about 1percent. Due to the cost of injecting chemicals, this low increase inoil recovery is rarely cost effective even though a slight increase inoil recovery efficiency producing an additional 1 percent of residualoil can represent billions of dollars.

A main limitation of water or chemical floods is that conventionalwell-injection techniques do not allow for wide-spread contact betweenthe injected fluid and the trapped oil. A way to evenly distribute theinjected fluid throughout a larger portion of the reservoir is neededfor enhancing oil recovery.

SUMMARY

A method is disclosed for enhancing hydrocarbon recovery in subterraneanreservoirs.

An injection well and a production well extend into a hydrocarbonbearing zone of the subterranean reservoir and are in fluidcommunication therewith. The method includes injecting an enhanced oilrecovery fluid into the hydrocarbon bearing zone through the injectionwell. An electric field is generated through at least a portion of thehydrocarbon bearing zone to induce electrokinetic migration of theenhanced oil recovery fluid. Hydrocarbons from the hydrocarbon bearingzone of the subterranean reservoir are recovered through the productionwell.

In one or more embodiments, a pair of electrodes generate the electricfield of less than 50 volts per meter (V/m) between the pair ofelectrodes, resulting in a direct current having a current densitybetween the electrodes of less than 20 amps/m2.

In one or more embodiments, the temperature of the hydrocarbon bearingzone between the electrodes is at a first temperature prior togenerating the electric field in the hydrocarbon bearing zone, thetemperature of the hydrocarbon bearing zone between the electrodes is ata second temperature following generating the electric field in thehydrocarbon zone, and wherein the second temperature is no more than 20°C. higher than the first temperature.

In one or more embodiments, the electric field is generated by emittinga direct current between a pair of electrodes having opposite chargesand being spaced apart from one another within the hydrocarbon bearingzone. In one or more embodiments, the electric field is generated byemitting a direct current between a first electrode coupled to theinjection well and a second electrode coupled to the production well. Inone or more embodiments, the direct current is periodically pulsed. Inone or more embodiments, the polarity of the pair of electrodes isperiodically reversed.

In one or more embodiments, the electric field is generated by emittinga direct current between a plurality of electrodes interspersed withinthe hydrocarbon bearing zone. The direct current emitted between one ormore of the plurality of electrodes can be adjusted such that theenhanced oil recovery fluid migrates to unswept areas of the hydrocarbonbearing zone.

In one or more embodiments, the enhanced oil recovery fluid comprises apolar fluid. In one or more embodiments, the enhanced oil recovery fluidhas a net total charge. In one or more embodiments, the enhanced oilrecovery fluid comprises water. In one or more embodiments, the enhancedoil recovery fluid comprises a surfactant. In one or more embodiments,the enhanced oil recovery fluid comprises an oxidant. In one or moreembodiments, the enhanced oil recovery fluid alters a physical propertyof a formation matrix of the hydrocarbon bearing zone.

According to another aspect of the present invention, a method isdisclosed for enhancing hydrocarbon recovery in subterranean reservoirs.The method includes providing an injection well and a production wellthat extend into and are in fluid communication with a hydrocarbonbearing zone of a subterranean reservoir and providing a pair ofelectrodes having opposite charges and being spaced apart from oneanother within the hydrocarbon bearing zone. An enhanced oil recoveryfluid is injected into the hydrocarbon bearing zone through theinjection well. A direct current is emitted between the pair ofelectrodes to induce electrokinetic migration of the enhanced oilrecovery fluid. Hydrocarbons are recovered from the hydrocarbon bearingzone of the subterranean reservoir through the production well.

In one or more embodiments, the voltage between electrodes is less thanabout 50 volts per meter. In one or more embodiments, the direct currentis periodically pulsed. In one or more embodiments, the polarity of thepair of electrodes is periodically reversed.

In one or more embodiments, an electrode of the pair of electrodes iscoupled to the injection well. In one or more embodiments, an electrodeof the pair of electrodes is coupled to the production well.

In one or more embodiments, the enhanced oil recovery fluid compriseswater. In one or more embodiments, the enhanced oil recovery fluidcomprises a surfactant. In one or more embodiments, the enhanced oilrecovery fluid comprises an oxidant. In one or more embodiments, theenhanced oil recovery fluid alters a physical property of a formationmatrix of the hydrocarbon bearing zone.

According to another aspect of the present invention, a method isdisclosed for enhancing hydrocarbon recovery in subterranean reservoirs.The method includes providing an injection well and a production wellthat extend into a hydrocarbon bearing zone of a subterranean reservoirand are in fluid communication therewith. A plurality of electrodes isinterspersed within the hydrocarbon bearing zone of a subterraneanreservoir. An enhanced oil recovery fluid is injected into thehydrocarbon bearing zone through the injection well. A direct current isemitted between the plurality of electrodes to induce electrokineticmigration of the enhanced oil recovery fluid. Hydrocarbons from thehydrocarbon bearing zone of the subterranean reservoir are recoveredthrough the production well.

In one or more embodiments, the direct current emitted between one ormore of the plurality of electrodes is adjusted such that the enhancedoil recovery fluid migrates to unswept areas of the hydrocarbon bearingzone.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic sectional view of an example oil recovery systemthat includes a reservoir that is in fluid communication with aninjection well and a production well during enhanced oil recoveryoperations, in accordance with an embodiment of the present invention.

FIG. 2 is a schematic sectional view of an example oil recovery systemthat includes a reservoir that is in fluid communication with aninjection well and a production well equipped with a pair of electrodesduring enhanced oil recovery operations, in accordance with anembodiment of the present invention.

DETAILED DESCRIPTION

The system and method described herein are directed to enhancing oilrecovery of reservoirs, particularly by maximizing the distribution ofan enhanced oil recovery fluid within a reservoir viaelectrokinetic-induced migration. A general treatise on conventionalenhanced oil recovery is, “Basic Concepts in Enhanced Oil RecoveryProcesses,” edited by M. Baviere (published for SCI by Elsevier AppliedScience, London and New York, 1991).

Referring to FIG. 1, subterranean reservoir 10 includes a plurality ofrock layers including hydrocarbon bearing strata or zone 11. Injectionwell 13 extends into hydrocarbon bearing zone 11 of subterraneanreservoir 10 such that injection well 13 is in fluid communication withhydrocarbon bearing zone 11. Subterranean reservoir 10 can be any typeof subsurface formation in which hydrocarbons are stored, such aslimestone, dolomite, oil shale, sandstone, or a combination thereof.Production well 15 is also in fluid communication with hydrocarbonbearing zone 11 of subterranean reservoir 10 in order to receivehydrocarbons therefrom. Production well 15 is positioned a predeterminedlateral distance away from injection well 13. For example, productionwell 15 can be positioned between 100 feet to 10,000 feet away frominjection well 13. As will be readily appreciated by those skilled inthe art, there can be additional injection wells 13 and production wells15, such that production wells 15 are spaced apart from injection wells13 at predetermined locations to optimally receive the hydrocarbonsbeing pushed due to injections from injection wells 13 throughhydrocarbon bearing zone 11 of subterranean reservoir 10. Furthermore,while not shown in FIG. 1, injection well 13 and production well 15 candeviate from the vertical position such that in some embodiments,injection well 13 and/or production well 15 can be a directional well,horizontal well, or a multilateral well.

As will be described in further detail below, in operation, an enhancedoil recovery (EOR) fluid 17 is injected into hydrocarbon bearing zone 11of subterranean reservoir 10 through injection well 13. The EOR fluid 17comprises a polar fluid or a fluid having a net total charge. Forexample, EOR fluid 17 can be water as it has an uneven distribution ofelectron density and therefore, comprises a polar molecule. In one ormore embodiments, EOR fluid 17 comprises a polar gas. In one or moreembodiments, EOR fluid 17 comprises a chemical or mixture of chemicalshaving a net total charge. For example, EOR fluid 17 can compriseoxidizing agents (e.g., peroxides, hypohalites, ozone, persulphates,permanganates), reducing agents (e.g. nascent hydrogen, organic acids),surfactants/co-surfactants, solvents/co-solvents, polymers, or acombination thereof.

In some embodiments, EOR fluid 17 alters the physical properties of theformation or rock matrix of hydrocarbon bearing zone 11 such as byincreasing the effective porosity and permeability of the matrix so thatthe hydrocarbons are more accessible and recoverable. For example, oilshale often contains large amounts of tightly bonded carbonates andpyrites that can be dissolved using acid, such as thiobacillus.Depletion of these carbonate minerals from the shale matrix, such asthrough bioleaching, results in newly formed cavities that effectivelyincreases the porosity (e.g., from less than 0.5% to about 4 or 5%) andpermeability of the oil shale, thereby enhancing recovery of thehydrocarbons. In some embodiments, EOR fluid 17 penetrates into porespaces of the formation contacting the trapped oil globules such thatthe oil trapped in the pore spaces of the reservoir rock matrix isreleased. For example, EOR fluid 17 can be a surface active agentreducing the interfacial tension between the water and oil in thesubterranean reservoir such that the oil trapped in the pore spaces ofthe reservoir rock matrix is released.

Referring to FIG. 1, an electric field is generated through at least aportion of the hydrocarbon bearing zone 11 to induce electrokineticmigration of EOR fluid 17. Electrokinetic induced migration allows forthe EOR fluid 17 to contact portions of the reservoir that previouslywere unswept due to the limitations of traditional hydraulic injection,thereby enhancing recovery of hydrocarbons from hydrocarbon bearing zone11 of subterranean reservoir 10 through production well 15. The electricfield is generated by electrodes that impose a low voltage directcurrent through at least the portion of the hydrocarbon bearing zone 11between injection well 13 and production well 15.

In one embodiment, one or more electrodes are placed in communicationwith injection well 13 such that the electrically charged injection wellacts as either an anode or a cathode. Similarly, one or more electrodesare placed in communication with production well 15 such that theelectrically charged production well acts as an opposing cathode oranode to injection well 13. The respective charges create an electriccurrent in the reservoir fluids contained within hydrocarbon bearingzone 11 of subterranean reservoir 10, which induces electrokineticmigration of EOR fluid 17 such that it is distributed within hydrocarbonbearing zone 11 of subterranean reservoir 10. One skilled in the artwill appreciate that additional electrodes can be placed in locationsother than in communication with injection well 13 and production well15, such that an electric field is created that is capable of directingEOR fluid 17 to a plurality of areas of within subterranean reservoir10. In some embodiments, the electrodes are positioned directly withinthe hydrocarbon bearing zone 11. In some embodiments, the electrodes arepositioned at locations above or below hydrocarbon bearing zone 11 suchas within rock layers adjacent to hydrocarbon bearing zone 11.

The electrodes can be made of any conductive material such as carbon orgraphite. Electrodes of carbon and graphite are generally more resistantto corrosion. In another embodiment, the electrodes are conductivepolymeric materials or intrinsically conducting polymers (ICPs), whichalso inhibit corrosion. In one embodiment, the electrodes create a lowvoltage direct current density of less than about 10 volts per meter(V/m). In another embodiment, the electrodes create a low voltage directcurrent density of less than about 20 volts per meter (V/m). In anotherembodiment, the electrodes create a low voltage direct current densityof less than about 50 volts per meter (V/m). In some embodiments, thelow voltage direct current is periodically pulsed or reversed, which canhelp prevent buildup of acidic conditions at the cathode. In oneembodiment, the frequency of pulsing and/or reversal of polarity is lessthan about a second. In another embodiment, the frequency of pulsingand/or reversal of polarity is greater than about a minute, such asranging from periods of minutes to days. The direct current densitygenerated in the hydrocarbon-bearing zone as a result of the low voltageapplied by the electrodes is sufficiently small, such that the zone isnegligibly heated during application of the voltage. In one embodiment,the emitted direct current has a current density of less than 5 amps/m2;in another embodiment, less than 0.5 amps/m2; in another embodiment,less than 10 amps/m2; in another embodiment, less than 20 amps/m2. Theamount of heating may be determined by determining an averagetemperature of the hydrocarbon-bearing zone between the electrodes. Afirst temperature is determined for the zone prior to application of thevoltage through the zone. A second temperature is determined for thezone at a steady-state condition during application of the voltage.Steady state in one embodiment is indicated by no measurable change intemperature as a result of the applied voltage. In one embodiment, thecurrent density is controlled to maintain a second temperature of thehydrocarbon-bearing zone that is no more than 25° C. higher than thefirst temperature; in other embodiments, no more than 20° C. higher; andno more than 10° C. higher than the first temperature; and no more than5° C. higher than the first temperature. Furthermore, if there is anytemperature increase, in one embodiment, the temperature increase isslow and steady increase (rather than instantaneous change) with noperceptible change in temperature (e.g., less than 1° C.) after a monthof applying the voltage.

FIG. 2 shows an embodiment of the present invention in which injectionwell 13 and production well 15 are equipped with a pair of electrodes21, 23, respectively. A power source 25 is provided such that thepositive and negative terminals are connected to electrodes 21, 23. Thesize of the power source is dependent on the size and characteristics ofthe reservoir. The size of the power source is however, large enough tosufficiently produce a low voltage direct current through at least aportion of the hydrocarbon bearing zone 11. In one embodiment, thepositive terminal of power source 25 is in communication with electrode21 such that electrode 21, which is coupled to injection well 13, actsas an anode. The negative terminal of power source 25 is incommunication with electrode 23 such that electrode 23, which is coupledto production well 15, acts as a cathode. In another embodiment, thepositive and negative terminals of the power source 25 are switched suchthat the positive terminal of power source 25 is in communication withelectrode 23 and the negative terminal of power source 25 is incommunication with electrode 21. Here, injection well 13 acts as thecathode and production well 15 acts as the anode. In either embodiment,the pair of electrodes 21, 23 generates an electric field through atleast a portion of the hydrocarbon bearing zone 11 to induceelectrokinetic migration of EOR fluid 17. In other embodiments (notshown in FIG. 2), electrodes 21, 23 are positioned in locations otherthan being coupled to injection well 13 and production well 15. Theelectrodes can also be positioned at locations above or belowhydrocarbon bearing zone 11 such as within rock layers adjacent tohydrocarbon bearing zone 11. Additionally, a plurality of electrodes canbe interspersed within subterranean reservoir 10 such that an electricfield is created to drive EOR fluid 17 to unswept areas withinhydrocarbon bearing zone 11.

Therefore, embodiments of the present invention utilizeelectrokinetic-induced migration to overcome the fluid channelinglimitations related to traditional hydraulic injection. In particular, alow voltage direct current is used to move or distribute EOR fluid 17within the saturated porous media of the reservoir. For example, polarfluids or fluids having a net charge, including water, gas, surfactants,dissolved species, colloids, and micelles, can be moved rapidly throughporous media under the influence of a direct current. In general, therate of movement is associated with the power output of the powersource, porosity of the reservoir matrix, and charge density. Further,the rate of migration of the EOR fluid 17 is independent of thehydraulic conductivity. Accordingly, as EOR fluid 17 migrates throughthe subterranean reservoir the rate of movement is independent of thepermeability and connectivity of the porous rock matrix. For example,EOR fluid 17 under electrokinetics migration can penetrate through rockshaving a very small porosity, such as a porosity of 0.02% or less. EORfluid 17 is therefore distributed to portions of the subterraneanreservoir where trapped oil is located, such as those areas wheretraditional enhanced oil recovery floods have not swept. One skilled inthe art will recognize that this is advantageous as injected EOR fluid17, such as water during an induced water flood, can be mobilized fromone portion of the reservoir where oil saturations are low into anotherportion of the reservoir where oil saturations are high.

In one embodiment, EOR fluid 17 penetrates into pore spaces of theformation contacting the trapped oil globules such that the oil trappedin the pore spaces of the reservoir rock matrix is released by reducingthe interfacial tension between the water and oil in the subterraneanreservoir. For example, EOR fluid 17 can comprise at least onesurfactant or a component that will produce at least one surfactant insitu having a net total charge. EOR fluid 17 can produce naturallyoccurring surfactants, such as from a biologically mediated reaction.Alternatively, EOR fluid 17 can produce surfactant in situ as aby-product of an induced process. For example, one or more compounds canbe injected into the reservoir such that they react with reservoirmaterials to produce a surfactant. In another embodiment, one or morecompounds can be injected into the reservoir that when mixed in the rockmatrix react with each other to produce surfactant. Examples ofsurfactants that can be utilized for as or in EOR fluid 17 includeanionic surfactants, cationic surfactants, amphoteric surfactants,non-ionic surfactants, and a combination thereof. As a skilled artisanmay appreciate, the surfactant(s) selection may vary depending upon suchfactors as salinity and clay content in the reservoir. The surfactantscan be injected in any manner such as in an aqueous solution, asurfactant-polymer (SP) flood or an alkaline-surfactant-polymer (ASP)flood. The surfactants can be injected continuously or in a batchprocess.

EOR fluid 17 can comprise anionic surfactants such as sulfates,sulfonates, phosphates, or carboxylates. Such anionic surfactants areknown and described in the art in, for example, SPE 129907 and U.S. Pat.No. 7,770,641, which are both incorporated herein by reference. Examplecationic surfactants include primary, secondary, or tertiary amines, orquaternary ammonium cations. Example amphoteric surfactants includecationic surfactants that are linked to a terminal sulfonate orcarboxylate group. Example non-ionic surfactants include alcoholalkoxylates such as alkylaryl alkoxy alcohols or alkyl alkoxy alcohols.Currently available alkoxylated alcohols include Lutensol® TDA 10EO andLutensol® OP40, which are manufactured by BASF SE headquartered inRhineland-Palatinate, Germany. Neodol 25, which is manufactured by ShellChemical Company, is also a currently available alkoxylated alcohol.Chevron Oronite Company LLC, a subsidiary of Chevron Corporation, alsomanufactures alkoxylated alcohols such as L24-12 and L14-12, which aretwelve-mole ethoxylates of linear carbon chain alcohols. Other non-ionicsurfactants can include alkyl alkoxylated esters and alkylpolyglycosides. In some embodiments, multiple non-ionic surfactants suchas non-ionic alcohols or non-ionic esters are combined. Thesurfactant(s) of EOR fluid 17 can be any combination or individualanionic, cationic, amphoteric, or non-ionic surfactant so long as EORfluid 17 has a net total charge.

In one embodiment, electrokinetics is utilized for environmentaltreatment of wastes (ex situ and/or in situ). In particular,electrokinetics can enhance chemical treatment of contaminated soil orsediment. The contaminant may be organic, such as oil or solvent, orinorganic, such as mercury and arsenic. The EOR fluid can include asurfactant that reduces the interfacial tension between oil and water,thereby increasing the solubility of the contaminant.

Applications of electrokinetic-induced migration are illustrated in U.S.Pat. No. 7,547,160 and in “Electrokinetic Migration of PermanganateThrough Low-Permeability Media,” by D. A. Reynolds et al., Ground Water,July-August 2008, 46(4), pp. 629-37, which are both incorporated hereinby reference. These publications illustrate rapid electrokinetic-inducedmigration of an oxidant (potassium permanganate) through lowpermeability clay material. In particular, the oxidant is deliveredthrough the low permeability clay material at orders of magnitude fasterthan that of hydraulically induced flow.

For example, the advantages of electrokinetic-induced migration overtraditional hydraulic delivery is illustrated in the followingexperiment. A thin glass tank having a width of about 4 cm wasconstructed to simulate a two-dimensional flow field through aheterogeneous porous media. House-brick sized pieces of clay, whichrepresent low permeability features, were emplaced within a zone ofcontiguous glass beads. The glass beads represent the high permeabilityzones of channeled flow. The tank was saturated with water and a flowfield was established across the apparatus by fixing the hydraulic head(water elevation) at different heights on either side of the tank.Potassium permanganate was introduced into one side of the tank andallowed to flow through the apparatus. The potassium permanganate wassubstantially distributed within the glass beads after two hours.However, essentially no infiltration into the clay bricks occurred,indicating that the potassium permanganate bypassed the low permeabilityzones. This experiment was repeated, however, an anode and cathode wereplaced at either end of the tank after the potassium permanganate hadflowed through the apparatus for two hours. A low voltage direct currentdensity of approximately 10 volts per meter (V/m) was applied betweenthe anode and cathode for 20 minutes. The clay blocks were dissected andshowed that the potassium permanganate fully penetrated the clay bricks.

Application of electrokinetic induced migration to enhance thedistribution of an EOR fluid is disclosed. Use of electrokinetic inducedmigration allows for the EOR fluid to contact portions of the reservoirthat previously were unswept due to the limitations of traditionalhydraulic injection. In some embodiments, the EOR fluid furtherpenetrates into pore spaces of the formation contacting the trapped oilglobules, thereby reducing the interfacial tension between the water andoil in the reservoir and releasing the oil from the pore spaces.

EXAMPLE

An electro-kinetic cell having a length of 40 inches and diameter of 4inches is prepared. Into the cell is placed 3 to 4 inches of the rocksample. Porous frits and coated electrodes are placed in both chambersat the end of the apparatus. The fluid chambers are filled with aqueoussolution containing a reagent in dissolved/ionic form. Fluid levels atcathode and anode chambers are maintained at almost the same level toavoid any hydraulic gradient. The electrodes are connected to a DCelectric power supply (Chroma 62000 P Power Supply). A constant voltagegradient of 1 to 1.5 VDC/cm is applied to the rock sample. The aqueoussolution containing the reagent is found to have migrated through therock sample in response to the applied voltage; the temperature increasein the rock sample during the test is negligible.

While in the foregoing specification this invention has been describedin relation to certain preferred embodiments thereof, and many detailshave been set forth for purpose of illustration, it will be apparent tothose skilled in the art that the invention is susceptible to alterationand that certain other details described herein can vary considerablywithout departing from the basic principles of the invention. Forexample, in one embodiment, electrokinetic migration is used to preventcorrosion or scale build-up in injection or production wells bymigrating polar gases, such as hydrogen sulfide (H₂S), to portions ofthe subterranean reservoir away from the wells. In this case, the polargases are naturally present in the reservoir rather than being injectedthrough the injection well like the EOR fluid.

What is claimed is:
 1. A method for enhancing hydrocarbon recovery insubterranean reservoirs, the method comprising: (a) providing aninjection well and a production well that extend into a hydrocarbonbearing zone of a subterranean reservoir and are in fluid communicationtherewith; (b) providing a pair of electrodes having opposite charges inthe hydrocarbon bearing zone, wherein the temperature of the hydrocarbonbearing zone between the electrodes is at a first temperature; (c)injecting an enhanced oil recovery fluid into the hydrocarbon bearingzone through the injection well; (d) generating an electric field ofless than 50 volts per meter (V/m) between the pair of electrodes andemitting a direct current having a current density of less than 20amps/m2 through at least a portion of the hydrocarbon bearing zone toinduce electrokinetic migration of the enhanced oil recovery fluid,wherein the current density is controlled to maintain a resultant secondtemperature of the hydrocarbon bearing zone that is no more than 20° C.higher than the first temperature; and (e) recovering hydrocarbons fromthe hydrocarbon bearing zone of the subterranean reservoir through theproduction well.
 2. The method of claim 1, wherein the electric field isgenerated by emitting a direct current between the pair of electrodesand wherein the electrodes are spaced apart between 100 feet to 10,000feet from one another within the hydrocarbon bearing zone.
 3. The methodof claim 1, wherein the electric field is generated by emitting a directcurrent between a first electrode coupled to the injection well and asecond electrode coupled to the production well.
 4. The method of claim1, wherein the electric field is generated by emitting a direct currentbetween a plurality of electrodes interspersed within the hydrocarbonbearing zone.
 5. The method of claim 1, wherein the electric field isgenerated by emitting a direct current having a current density of lessthan 10 amps/m2 between the pair of electrodes.
 6. The method of claim1, wherein the generated electric field is less than 20 volts per meter.7. The method of claim 1, wherein the current density is controlled tomaintain a resultant second temperature of the hydrocarbon bearing zonethat is no more than 10° C. higher than the first temperature.
 8. Themethod of claim 1, wherein the enhanced oil recovery fluid comprises anyof water, a surfactant, an oxidant, and mixtures thereof.
 9. The methodof claim 1, wherein the enhanced oil recovery fluid alters a physicalproperty of a formation matrix of the hydrocarbon bearing zone.
 10. Amethod for enhancing hydrocarbon recovery in subterranean reservoirs,the method comprising: (a) providing an injection well and a productionwell that extend into a hydrocarbon bearing zone of a subterraneanreservoir and are in fluid communication therewith; (b) providing a pairof electrodes having opposite charges and being spaced apart from oneanother within the hydrocarbon bearing zone, wherein the temperature ofthe hydrocarbon zone between the electrodes is at a first temperature;(c) injecting an enhanced oil recovery fluid into the hydrocarbonbearing zone through the injection well; (d) emitting a direct currenthaving a current density of less than 20 amps/m2 between the pair ofelectrodes to induce electrokinetic migration of the enhanced oilrecovery fluid, wherein the current density is controlled to maintain aresultant second temperature of the hydrocarbon bearing zone that is nomore than 20° C. higher than the first temperature; and (e) recoveringhydrocarbons from the hydrocarbon bearing zone of the subterraneanreservoir through the production well.
 11. The method of claim 10,wherein the current density is less than 10 amps/m2.
 12. The method ofclaim 10, wherein an electric field of less than 20 volts per meter isgenerated between the pair of electrodes.
 13. The method of claim 10,wherein the direct current is periodically pulsed.
 14. The method ofclaim 10, wherein polarity of the pair of electrodes is periodicallyreversed.
 15. The method of claim 10, wherein one electrode of the pairof electrodes is coupled to the injection well and one electrode of thepair of electrodes is coupled to the production well.
 16. The method ofclaim 10, wherein the enhanced oil recovery fluid comprises any ofwater, surfactant, an oxidant, and combinations thereof.
 17. A methodfor enhancing hydrocarbon recovery in subterranean reservoirs, themethod comprising: (a) providing an injection well and a production wellthat extend into a hydrocarbon bearing zone of a subterranean reservoirand are in fluid communication therewith; (b) providing a pair ofelectrodes within the hydrocarbon bearing zone of a subterraneanreservoir, wherein the temperature of the hydrocarbon bearing zonebetween the electrodes is at a first temperature; (c) injecting anenhanced oil recovery fluid into the hydrocarbon bearing zone throughthe injection well; (d) generating an electric field of less than 50volts per meter (V/m) between the pair of electrodes and emitting adirect current between the pair of electrodes to induce electrokineticmigration of the enhanced oil recovery fluid, wherein the direct currentbetween the pair of electrodes is controlled to have a current densitysuch that a resultant second temperature of the hydrocarbon bearing zonethat is no more than 20° C. higher than the first temperature; and (e)recovering hydrocarbons from the hydrocarbon bearing zone of thesubterranean reservoir through the production well.
 18. The method ofclaim 17, further comprising: (f) adjusting the direct current emittedbetween the pair of electrodes such that the enhanced oil recovery fluidmigrates to unswept areas of the hydrocarbon bearing zone.
 19. Themethod of claim 17, wherein the current density is less than 10 amps/m2.20. The method of claim 17, wherein the resultant second temperature ofthe hydrocarbon bearing zone is no more than 5° C. higher than the firsttemperature.